ISO Stakeholder Initiative Process For TPS POLICY AND PLAN - PowerPoint PPT Presentation

ISO Stakeholder Initiative Process For TPS POLICY AND PLAN DEVELOPMENT Paper Proposal Final Board Proposal Stakeholder Input We are here

Agenda – May 20, 2011 ISO Planning Standards Stakeholder Conference Call 1. Introductions and Meeting Arrangements 2. Standards A. SF/GBA generation outage - retired B. Combined line and generator outage – no change C. Specific nuclear units – no change D. Combined cycle module as G-1 – added E. Voltage - added F. New transmission vs. involuntary load interruption – revised 3. Guidelines A. New Special Protection Systems – revised 4. Glossary and Other Stakeholder Comments 5. Next Steps and Schedule

ISO Planning Standards Catalin Micsa Lead Regional Transmission Engineer Stakeholder Meeting May 20, 2011

Existing Standards and Criteria During its planning activities ISO must :  Follow all NERC Reliability Standards like http://www.nerc.com/page.php?cid=2|20  Transmission Planning (TPL)  Nuclear Plant Interface Requirements (NUC-001)  Follow all WECC Regional Criteria http://www.wecc.biz/Standards/WECC%20Criteria/Forms/AllItems.aspx  Follow ISO Planning Standards Slide 4

New Structure and Documentation for the ISO Planning Standards Standards:  Combined Line and Generator Outage Standard  Voltage  Specific Nuclear Unit  Loss of Combined Cycle Power Plant Module as a Single Generator Outage  Planning for New Transmission versus Involuntary Load Interruption Guidelines:  New Special Protection Systems Slide 5

Retirement of San Francisco Greater Bay Area Generation Outage Standard:  Eliminated requirements related to Hunters Point and Potrero  San Francisco reliability is independent of generation requirement  New transmission infrastructure has reduced the Greater Bay Area’s overall dependence on generation  Additional planned transmission infrastructure will further diminish the Greater Bay Area’s overall dependence on generation No stakeholder comments received Slide 6

Some standards were not changed Combined Line and Generator Outage Standard:  One generator out of service followed by system readjustment and a single line outage should meet NERC TPL002 reliability standard for single contingencies Specific Nuclear Unit Standards:  Respect Appendix E of the Transmission Control Agreement regarding nuclear power plants http://www.caiso.com/docs/09003a6080/25/a3/09003a608025a3bd.pdf No stakeholder comments received Slide 7

Old enforcement is now a standard Loss of Combined Cycle Power Plant Module as a Single Generator Outage Standard:  ISO has consistently enforced this standard  Measure is based on historical data and “greater than 1 event over a 3 year period”  Exceptions are possible  After 2 years of operation  Supported by historical data  Addressed on a case by case base only Stakeholder comments:  Add definition of Combine Cycle Power Plant Module - done Slide 8

New standard is proposed Voltage Standard:  Common denominator is envisioned across ISO  Low voltage and voltage deviation apply to load (including generator auxiliary load) buses  High voltage apply to all buses  Exceptions allowed if vetted through open process Contingency Conditions (TPL-002 & Normal Conditions (TPL-001) Voltage Deviation TPL-003) Voltage level Vmin (pu) Vmax (pu) Vmin (pu) Vmax (pu) TPL-002 TPL-003 <= 200 kV 0.95 1.05 0.90 1.1 ≤5% ≤10% >= 200 kV 0.95 1.05 0.90 1.1 ≤5% ≤10% >= 500 kV 1.0 1.05 0.90 1.1 ≤5% ≤10% Slide 9

Stakeholder comments Voltage Standard:  Upper voltage too high at 1.1 pu - reduced to 1.05 pu  Vmin needed for 500 kV since due to generator auxiliary loads - done  Exceptions are allowed - done  Impact of new standard – ISO estimates small since it is a least common denominator  Elaborate on process for exceptions – done on a yearly bases and coordinated through regularly scheduled TPP stakeholder meetings  Clarify that the per unit (pu) is based on nominal voltage – done  All have been addressed Slide 10

Revised standard Planning for New Transmission versus Involuntary Load Interruption Standard:  Continues to rely on NERC standards and WECC regional criteria  New write-up and changes will address:  Caps amount of involuntary load interruption based on WECC self imposed reporting requirements  Establishes a maximum level for radial substations  Establishes minimum sizing of back-tie(s) for radial loads  Allows justification of transmission reinforcements through BCR calculation on a case by case basis Slide 11

Planning for New Transmission versus Involuntary Load Interruption Standard 1. No single contingency with load drop above 250 MW  Cap NERC TPL002 footnote for single contingencies  Avoids WECC reporting requirements for single contingencies 2. All substations of 100 MW or more need to be looped  Standardize PTOs substations design  Does not preclude substations with less then 100 MW from being looped in Slide 12

Planning for New Transmission versus Involuntary Load Interruption Standard 3. Minimum size for back-tie(s)  Most stringent between 50% of peak load or 80% of the hours in the year (based on actual load shape for the area)  Maintains a minimum level of back-tie(s) in order to assure a minimum level of service consistent across the system 4. Benefit to Cost Ratio > 1 may justify upgrades  Allow elimination or reduction in load drop exposure if it has overall economic benefits  BCR calculation to be supplied with the project through the open window and discussed in an open stakeholder process Slide 13

Stakeholder comments Planning for New Transmission versus Involuntary Load Interruption Standard:  General concerns about magnitude and cost impact to ratepayers – addressed by downgrading to a guideline for the first year, if impact is great this standard can be changed next year  Allow exceptions – not needed in the first year (guideline)  Needs definition of “available back-tie” – under consideration  Apply the 250 MW cap on category C as well and/or apply two different limits for category B (based on configuration) plus higher and different limits on category C outages (based on connecting voltage level – under further consideration and discussion maybe next year after the impact of current changes are available Slide 14

This guideline was slightly modified New Special Protection Systems Guideline:  Small revisions to the existing guidelines  Applies to new SPS for both load and generation  Eliminated restriction on SPS for RMR units  No changes to maximum arming amounts  Increased the number of contingencies (single or double) that would trigger the operation of SPS from 4 to 6 local contingencies Slide 15

Stakeholder comments New Special Protection Systems Guideline :  Open SPS performance review process – part of regularly scheduled TPP stakeholder meetings  Frequency of existing involuntary load trip may not be increased as a result of a new generation addition – ISO believes that impact is small and can be addressed during the SPS performance review  Involuntary load tripping should be last resort - done  Refer to the WECC Remedial Action Scheme Design Guide – done  Evaluate SPS on a case-by-case bases – ISO believes a guideline is required Slide 16

Glossary Here are a few examples:  Bulk Electric System – all facilities under ISO control  Development of load models – PTOs, UDCs and others  Development of load forecast – CEC  Timed allowed for manual readjustment – less than 30 minutes Stakeholder comments:  Keep NERC and WECC definition of Bulk Electric System – under legal review  Change “Time allowed for manual readjustment” to facility ratings – ISO believes that we should hold our practices at or above what is required by and for our neighboring systems Slide 17

Other stakeholder comments  Explain why ISO needs to have any reliability standards  Explain the need for each individual standard  Add a “Critical T-1/G-1” standards as category B contingency  Add a reactive margin criteria based on fixed MVAR quantity  Add common “duct line” as credible C5 contingencies  Include LCR and Deliverability Assessment under the Planning Standards  Develop criteria for establishing uniform equipment rating criteria among PTOs  Address modeling issues like: DG, DR or generator Pmin  Add more time and iterations to this stakeholder process Slide 18

Next Steps - Schedule Overall timeline – Post draft ISO Planning Standards April 25, 2011 – Stakeholder Meeting to discus changes May 2, 2011 – Submit comments by May 9, 2011 – Posting of second draft ISO Planning Standards May 13, 2011 – ISO Stakeholder conference call May 20, 2011 – Submit comments by May 27, 2011 – Finalize ISO Planning Standards June 2, 2011 – ISO Board of Governors June 29-30, 2011 – Implementation July 1, 2011 Your comments and questions are welcome. Your comments and questions are welcome. For written comments, please send to: RegionalTransmission@caiso.com Slide 19